Petrophysical Evaluation of Gas Shale Reservoirs

Labani, Mohammad Mahdi; Rezaee, Reza

doi:10.1002/9781119039228.ch6

Cited by 7 publications

(6 citation statements)

References 67 publications

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“…In shale petroleum resource appraisal, the current practice of "volume = porosity × hydrocarbon saturation" is largely based on the understanding of conventional reservoir, and the resulting estimates often yield large uncertainties in resource volume and provide no information with respect to oil mobility. Many laboratory methods designed for conventional reservoirs could be problematic for measuring porosity and water saturation in shale reservoirs (e.g., Passey et al, 2010;Bohacs et al, 2013;Hartigan, 2014). Uncertainties arise because of the presence of large amount of clay minerals (e.g., Passey et al, 2010) and multiscale porous media with different origins and physical/chemical properties in shale reservoirs (Passey et al, 2010;Akkutlu and Fathi, 2012;Bohacs et al, 2013;Hartigan, 2014;Chen et al, 2017b).…”

Section: Introductionmentioning

confidence: 99%

A method for evaluating resource potential and oil mobility in liquid-rich shale plays—An example from upper Devonian Duvernay formation of the Western Canada Sedimentary Basin

Chen

Reyes²,

Liu³

et al. 2023

Front. Earth Sci.

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This paper discusses methods of assessing oil and gas resources and evaluating their mobility in shale reservoirs using programed pyrolysis data in conjunction with reservoir engineering parameters derived from production data. The hydrocarbon resource is calculated from the measured free hydrocarbon by programed pyrolysis with correction of evaporative loss that occurred during coring, storage and sample preparation. The correction takes account of the loss of light hydrocarbon fluids as a result of phase change during core retrieval to the surface and evaporative loss related to storage and sample preparation. Based on their response to ramping temperature during sample pyrolysis and thermal equilibrium behavior of distinct petroleum products at different thermal maturities, the estimated oil and gas resources are divided into three categories: non-movable, restricted, and movable to characterize the mobility of the petroleum fluids. The mobility classification is compared with oil compositional grouping based on evaporative kinetics of petroleum products in rock samples to examine their affinity. Pyrolysis analysis results from naturally matured samples and production data from different fluid zones in the Duvernay Shale resource play in Western Canada Sedimentary Basin (WCSB) were used to demonstrate the application of the proposed method. While the mobility of petroleum fluids increases with thermal maturation in general, the total movable resource reaches its maximum at the end of oil generation window, then declines as a result of massive loss due to hydrocarbon expulsion towards to gas window where liquids are thermally cracked to gaseous hydrocarbons. Compositional grouping based on evaporative kinetics does not show a complete accordance with mobility grouping, suggesting composition is only one of many factors affecting hydrocarbon fluid flow in shale reservoir. More studies are required to better understand the fundamentals of oil mobility in shale reservoir.

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Section: Introductionmentioning

confidence: 99%

A method for evaluating resource potential and oil mobility in liquid-rich shale plays—An example from upper Devonian Duvernay formation of the Western Canada Sedimentary Basin

Chen

Reyes²,

Liu³

et al. 2023

Front. Earth Sci.

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“…Yunosuke SAWA 1) , Yunfeng LIANG 2) , Sumihiko MURATA 3) , Toshifumi MATSUOKA 4) , Takashi AKAI 5) , and Sunao TAKAGI Characteristics of CH4 adsorption and CH4 replacement with CO2 in kerogen micropores were investigated by molecular dynamics (MD) simulations to obtain accurate estimates of CH4 volume and reduction of environmental load by applying multi-stage CO2 fracking for shale gas development. Firstly, CH4 density in the kerogen micropores was found to be about 1.8 times higher than in the mesopores outside the kerogen, indicating that an adsorption model accounting for the micropore filling is essential to correctly evaluate the volume of CH4 adsorption.…”

Section: Molecular Dynamics Simulation Of Adsorption and Replacement mentioning

confidence: 99%

Molecular Dynamics Simulation of Adsorption and Replacement of Methane in Kerogen Micropores

Sawa

Liang

Murata

et al. 2017

J. Jpn. Petrol. Inst.

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Characteristics of CH4 adsorption and CH4 replacement with CO2 in kerogen micropores were investigated by molecular dynamics (MD) simulations to obtain accurate estimates of CH4 volume and reduction of environmental load by applying multi-stage CO2 fracking for shale gas development. Firstly, CH4 density in the kerogen micropores was found to be about 1.8 times higher than in the mesopores outside the kerogen, indicating that an adsorption model accounting for the micropore filling is essential to correctly evaluate the volume of CH4 adsorption. Secondly, CO2 molecules with linear shape easily passed through the throat of the kerogen micropore, whereas CH4 molecules with regular tetrahedron shape did not. Thirdly, CH4 was easily replaced by CO2 in the kerogen micropores due to the higher affinity for CO2 than CH4 of oxygen atoms, which are much more common than other heteroatoms in the kerogen molecule. Finally, H2O molecules in the kerogen micropores and mesopores were aggregated by hydrogen bonding around the heteroatoms and prevented the replacement of CH4 by blocking the pathways.

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“…Multiple publications characterize the porosity [11,12], the porous structure, and permeability of tight sands, shales, and carbonates [13][14][15]. Based on published papers, we summarized conventional methods (basic in core analysis) and unconventional methods (widely applied for tight rock characterization) (Table 1).…”

Section: Introductionmentioning

confidence: 99%

Reservoir Properties of Low-Permeable Carbonate Rocks: Experimental Features

et al. 2020

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This paper presents an integrated petrophysical characterization of a representative set of complex carbonate reservoir rock samples with a porosity of less than 3% and permeability of less than 1 mD. Laboratory methods used in this study included both bulk measurements and multiscale void space characterization. Bulk techniques included gas volumetric nuclear magnetic resonance (NMR), liquid saturation (LS), porosity, pressure-pulse decay (PDP), and pseudo-steady-state permeability (PSS). Imaging consisted of thin-section petrography, computed X-ray macro- and microtomography, and scanning electron microscopy (SEM). Mercury injection capillary pressure (MICP) porosimetry was a proxy technique between bulk measurements and imaging. The target set of rock samples included whole cores, core plugs, mini cores, rock chips, and crushed rock. The research yielded several findings for the target rock samples. NMR was the most appropriate technique for total porosity determination. MICP porosity matched both NMR and imaging results and highlighted the different effects of solvent extraction on throat size distribution. PDP core-plug gas permeability measurements were consistent but overestimated in comparison to PSS results, with the difference reaching two orders of magnitude. SEM proved to be the only feasible method for void-scale imaging with a spatial resolution up to 5 nm. The results confirmed the presence of natural voids of two major types. The first type was organic matter (OM)-hosted pores, with dimensions of less than 500 nm. The second type was sporadic voids in the mineral matrix (biogenic clasts), rarely larger than 250 nm. Comparisons between whole-core and core-plug reservoir properties showed substantial differences in both porosity (by a factor of 2) and permeability (up to 4 orders of magnitude) caused by spatial heterogeneity and scaling.

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Petrophysical Evaluation of Gas Shale Reservoirs

Cited by 7 publications

References 67 publications

A method for evaluating resource potential and oil mobility in liquid-rich shale plays—An example from upper Devonian Duvernay formation of the Western Canada Sedimentary Basin

A method for evaluating resource potential and oil mobility in liquid-rich shale plays—An example from upper Devonian Duvernay formation of the Western Canada Sedimentary Basin

Molecular Dynamics Simulation of Adsorption and Replacement of Methane in Kerogen Micropores

Reservoir Properties of Low-Permeable Carbonate Rocks: Experimental Features

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